This page provides a reservoir management case study for a sandstone field under strong waterdrive in which crestal gas injection techniques have been implemented. Production from this field is from several Upper Cretaceous sandstone formations. The producing zones are in pressure communication in the gas cap and aquifer but separate in the oil column. The structure is a complexly faulted anticline with a major fault separating the west and east flanks. There is minor communication across the fault.
This page provides a reservoir management case study for a low-permeability sandstone field in which waterflooding techniques have been implemented. The reservoir is a series of Cretaceous-age, prograding delta clastic sediments consisting of laminated fine-grained sands and shales that are trapped stratigraphically by overlying shales. The primary recovery mechanism was solution-gas drive. The field was converted to waterflood in 1961 with an inverted nine-spot injection pattern. Subsequently, a portion of the field was converted to line-drive water injection for improved sweep efficiency and increased water injection capacity.
This page provides several reservoir management case studies that illustrate carbonate reservoirs in which waterflooding and miscible gas injection techniques have been implemented. This field produces primarily from a Jurassic-age limestone-dolomite section that has a simple plunging anticline structure. The updip trap is formed by a combination of facies change from dolomite to dense limestone and a bounding fault. The formation is layered and has been divided into 18 correlative zones. The field was developed competitively by several operators.
This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
An exploration well drilled by Wintershall on its Dvalin North prospect in the Norwegian Sea has encountered a significant gas reservoir. The discovery at Dvalin North is estimated to hold to hold 33–70 million BOE and is just 12 km north of the company's operated Dvalin field and 65 km north of the operated Maria field. The well also encountered hydrocarbons in two shallower secondary targets, with a combined resource estimate of 38–87 million BOE, making the potential for the field in excess of 150 million BOE. The well, drilled by the Deepsea Aberdeen rig, encountered gas, condensate, and oil columns of 33 m and 114 m in the Cretaceous Lysing and Lange formations, respectively. In the primary target in the Garn Formation, the well found a gas column of 85 m.
Eni encountered natural-gas-bearing sands with its Maha 2 well in the West Ganal Block offshore Indonesia. Drilled to a depth of 2970 m in 1115 m water depth, the well encountered 43 m of gas-bearing net sands in levels of Pliocene Age, according to the operator. A production test, which was limited by surface facilities, recorded a gas deliverability of the reservoir flowing at 34 MMscf/D. The operator collected data and samples during the test, to study in preparation of a field development plan for the Maha field. Two additional appraisal wells are planned for the discovery.
This article presents brief summaries of detailed petrophysical evaluations of several fields that have been described in the SPE and Soc. of Professional Well Log Analysts (SPWLA) technical literature. These case studies cover some of the complications that occur when making net-pay, porosity, and water saturation (Sw) calculations. Prudhoe Bay is the largest oil and gas field in North America with more than 20 billion bbl of original oil in place (OOIP) and an overlying 30 Tscf gas cap. In the early 1980s, the unit operating agreement required that a final equity determination be undertaken. In the course of this determination, an extensive field coring program was conducted, which resulted in more than 25 oil-based mud (OBM) cores being cut in all areas of the field and some conventional water-based mud (WBM) and bland-mud cores in other wells.
LLOG Exploration has started production from the Praline field in Mississippi Canyon Block 74 of the US Gulf of Mexico. The Praline subsalt well was drilled in 2,600 ft of water to a total depth of 13,400 ft and encountered over 125 ft of net Pliocene-aged hydrocarbons. The well was originally drilled in the spring of 2017 but was completed in August 2020 and has been tied back to the Talos Energy-operated Pompano platform in nearby Viosca Knoll Block 989 in 1,290 ft of water. LLOG operates Praline with a 27.25% working interest. Partners in the field are entities managed by Ridgewood Energy, including ILX Holdings, Red Willow Offshore, Houston Energy, and CL&F Offshore.
Occidental Petroleum (Oxy) said this week it has agreed to sell almost 25,000 net acres in the Permian Basin of Texas to Colgate Energy Partners III for nearly $508 million. Average output of the properties amounts to 10,000 BOE/D from about 360 wells in the southern Delaware Basin, Houston-based Oxy reported in its announcement. The sale, expected to close in the third quarter, will boost Midland-based Colgate's holdings in the Permian to about 83,000 acres with an estimated production of 55,000. Colgate said it plans to run up to six drilling rigs by year's end and boost average production to 75,000 BOE/D by 2022. Proceeds from the sale will be used to pay down Oxy's debt that was around $35.4 billion in March, down slightly from the $36.03-billion debt reported last June.